Swellable choke packer

ABSTRACT

There is provided a swellable choke having a tubular component and at least one swelling element. Each swelling element has a swelling material carried by the tubular component, the swelling material swelling in reaction to contact with a triggering substance, such as a fluid. Each swelling element also has a ring carried by the tubular component, the ring having an outer surface that moves from a first diameter to an expanded diameter as the swelling material increases in size.

RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional PatentApplication No. 62/157,229 filed May 5, 2015, which is herebyincorporated by reference in its entirety.

TECHNICAL FIELD

This relates to packers, such as may be used in SAGD or other downholeoperations to control flow.

BACKGROUND

In SAGD (steam assisted gravity drainage) operations, steam is injectedinto a well in order to heat and mobilize heavy oil in an oil-bearingformation. Steam is injected through an injection tubing string, andreturns through an annulus that is formed between the casing and theinjection string. An isolation packer is generally installed between theinjection tubing string and the casing in order to control thecirculation of the steam. Packers may also be used in other downholeoperations and in other types of wells, such as cyclic wells, whichgenerally have one leg that is used for both stimulation and production.Alternatively, steam flow control devices and production inflow controldevices may be used to control fluid flow.

Commonly used packers include cup-type packers, full swellable packers,and packing metal ring packers. In addition, PCT Patent Publication No.WO 2012/0136258 (Aakre et al.) entitled “Temperature Responsive Packerand Associated Hydrocarbon Production System” discloses a packer with afluid-filled bellows that expands when heated to restrict the annulus.

SUMMARY

According to an aspect, there is provided a swellable choke packerincluding a tubular component and at least one swelling element, eachswelling element including a swelling material carried by and,optionally, in thermal contact with the tubular component, the swellingmaterial increasing in size when contacting a triggering substance, andoptionally as the tubular component is heated; and a ring carried by thetubular component, the ring having an outer surface that moves from afirst diameter to an expanded diameter as the swelling material swells.

According to another aspect, the triggering substance may include wateror a hydrocarbon.

According to another aspect, the ring may be a split ring and the ringmay shield the swelling element from wear.

According to another aspect, the ring may be made from spring steel,stainless steel, a different metal or a composite.

According to another aspect, the swelling material may be aheat-responsive rubber that further expands in response to being heated.

According to another aspect, the swellable choke may further comprisetwo or more swelling elements axially spaced along the tubularcomponent.

According to another aspect, each swelling element may comprise a spacerelement positioned axially adjacent to each side of the swellingmaterial.

According to another aspect, the spacer elements may restrict expansionof the swelling material to a radial direction and provide a sealsurface within the choke.

According to another aspect, the tubular component may be a mandrel.

According to another aspect, there is provided a method of treating ahydrocarbon-producing well, including the steps of: providing aswellable choke according to the invention; attaching the swellablechoke in line with a tubing string; inserting the tubing string into thehydrocarbon-producing well; and changing at least one downhole conditionto cause the swellable choke to swell and engage an inner surface of thehydrocarbon-producing well.

According to another aspect, the downhole condition may be changed bycausing at least one of water or hydrocarbons to come into contact withthe swellable choke.

According to another aspect, the downhole condition may be changed bychanging the temperature to which the swellable choke is exposed.

According to another aspect, the ring may be allowed to slide along aninner surface of the hydrocarbon-producing well as the swellable chokemoves along the hydrocarbon-producing well.

In other aspects, the features described above may be combined togetherin any reasonable combination as will be recognized by those skilled inthe art.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features will become more apparent from the followingdescription in which reference is made to the appended drawings, thedrawings are for the purpose of illustration only and are not intendedto be in any way limiting, wherein:

FIG. 1 is a side elevation view of an expanding isolation packer.

FIG. 2 is a front elevation view of the expanding isolation packer shownin FIG. 1.

FIG. 3 is a perspective view of the expanding isolation packer shown inFIG. 1.

FIG. 4 is a cross-section of the side elevation view of the expandingisolation packer shown in FIG. 1.

FIG. 5 is a cut-away side elevation view of a SAGD injector withexpanding isolation packers.

FIG. 6 is a side elevation view of the SAGD injector shown in FIG. 5.

FIG. 7 is a side elevation view of the portion of the SAGD injector ofFIG. 5 shown in circle A, showing an expanding isolation packer.

FIG. 8 is a side elevation view of the portion of the SAGD injector ofFIG. 5 shown in circle B, showing a flow control device.

DETAILED DESCRIPTION

A detailed description of one or more embodiments of the invention isprovided below along with accompanying figures that illustrate theprinciples of the invention. The invention is described in connectionwith such embodiments, but the invention is not limited to anyembodiment. The scope of the invention is limited only by the claims andthe invention encompasses numerous alternatives, modifications andequivalents. Numerous specific details are set forth in the followingdescription in order to provide a thorough understanding of theinvention. These details are provided for the purpose of example and theinvention may be practiced according to the claims without some or allof these specific details. For the purpose of clarity, technicalmaterial that is known in the technical fields related to the inventionhas not been described in detail so that the invention is notunnecessarily obscured.

The term “invention” and the like mean “the one or more inventionsdisclosed in this application”, unless expressly specified otherwise.

The terms “an aspect”, “an embodiment”, “embodiment”, “embodiments”,“the embodiment”, “the embodiments”, “one or more embodiments”, “someembodiments”, “certain embodiments”, “one embodiment”, “anotherembodiment” and the like mean “one or more (but not all) embodiments ofthe disclosed invention(s)”, unless expressly specified otherwise.

The term “variation” of an invention means an embodiment of theinvention, unless expressly specified otherwise.

A reference to “another embodiment” or “another aspect” in describing anembodiment does not imply that the referenced embodiment is mutuallyexclusive with another embodiment (e.g., an embodiment described beforethe referenced embodiment), unless expressly specified otherwise.

The terms “including”, “comprising” and variations thereof mean“including but not limited to”, unless expressly specified otherwise.

The terms “a”, “an” and “the” mean “one or more”, unless expresslyspecified otherwise. The term “plurality” means “two or more”, unlessexpressly specified otherwise. The term “herein” means “in the presentapplication, including anything which may be incorporated by reference”,unless expressly specified otherwise.

The term “e.g.” and like terms mean “for example”, and thus does notlimit the term or phrase it explains.

The term “respective” and like terms mean “taken individually”. Thus iftwo or more things have “respective” characteristics, then each suchthing has its own characteristic, and these characteristics can bedifferent from each other but need not be. For example, the phrase “eachof two machines has a respective function” means that the first suchmachine has a function and the second such machine has a function aswell. The function of the first machine may or may not be the same asthe function of the second machine.

Where two or more terms or phrases are synonymous (e.g., because of anexplicit statement that the terms or phrases are synonymous), instancesof one such term/phrase does not mean instances of another suchterm/phrase must have a different meaning. For example, where astatement renders the meaning of “including” to be synonymous with“including but not limited to”, the mere usage of the phrase “includingbut not limited to” does not mean that the term “including” meanssomething other than “including but not limited to”.

Neither the Title (set forth at the beginning of the first page of thepresent application) nor the Abstract (set forth at the end of thepresent application) is to be taken as limiting in any way the scope ofthe disclosed invention(s). An Abstract has been included in thisapplication merely because an Abstract of not more than 150 words isrequired under 37 C.F.R. Section 1.72(b) or similar law in otherjurisdictions. The title of the present application and headings ofsections provided in the present application are for convenience only,and are not to be taken as limiting the disclosure in any way.

Numerous embodiments are described in the present application, and arepresented for illustrative purposes only. The described embodiments arenot, and are not intended to be, limiting in any sense. The presentlydisclosed invention(s) are widely applicable to numerous embodiments, asis readily apparent from the disclosure. One of ordinary skill in theart will recognize that the disclosed invention(s) may be practiced withvarious modifications and alterations, such as structural and logicalmodifications. Although particular features of the disclosedinvention(s) may be described with reference to one or more particularembodiments and/or drawings, it should be understood that such featuresare not limited to usage in the one or more particular embodiments ordrawings with reference to which they are described, unless expresslyspecified otherwise.

A swellable choke packer, generally identified by reference numeral 10,will now be described with reference to FIG. 1 through 8. As usedherein, the term choke refers to an element that restricts fluid flow ina wellbore, but does not necessarily provide against flow, and may nothold constant pressure against the fluid flow.

Referring to FIG. 1, swellable choke 10 has a tubular component 12, suchas a mandrel. Choke 10 as shown has two swelling elements 14, but mayalso have only one or may have more than two. Referring to FIG. 4, eachswelling element 14 includes a swelling material 16 that swells in thepresence of a particular substance, such as water, hydrocarbons, acompound that is reactive to swelling material 16, or a combination ofany or all of the foregoing. Swelling material 16 is carried by thetubular component, and is in thermal contact with the tubular component.Swelling material 16 is selected from different swellable materials,such as a swellable rubber, as are known in the art. The swellablematerial can be any material with a sufficiently high coefficient ofexpansion. While swelling material 16 may be a temperature-responsivematerial as well, it will be understood that swelling material reliesprimarily on water, hydrocarbons, or both as an actuator to swell. In anembodiment of the invention swellable material 16 absorbs fluids causingthe swelling to occur. Furthermore, as swelling material 16 is generallyintended to be used in high temperature and pressure applications, itwill preferably be selected to withstand these conditions sufficientlyto accomplish its intended use.

Each swelling element 14 has an outer ring 18 carried by tubularcomponent 12, where outer ring 18 has an outer surface 20 that movesfrom a retracted outer diameter to an expanded outer diameter asswelling material 16 increases in size. Outer ring 18 is formed suchthat it is provided with the ability to expand from a first diameter toan expanded diameter, as will be understood by those skilled in the art.For example, the outer ring may be a split ring as shown in FIG. 3,allowing outer ring 18 to expand. Outer ring 18 is preferably formedfrom a metal, such as spring steel, or stainless steel, a differentmetal or a composite that allows for a sliding engagement between outerring 18 and the casing string of the well as the ring 18 expands, whilealso resisting such elements as wear, high temperature and pressure,chemicals, etc., thereby protecting swelling material 16 from wearduring movement and choke flow. The material for outer ring 18 may beselected by those of ordinary skill to have the necessary propertiesbased on the anticipated degree of expansion and force applied and maybe any material suitable for the purpose. Preferably, outer ring 18 ismade from a material that has a low enough coefficient of frictionrelative to the inner surface of the casing that it is able to slidewithin the casing or liner as the inner or outer tubing strings moverelative to each other, such as may occur when repositioning a tubingstring, or due to the thermal expansion of metal.

Referring to FIG. 3, choke 10 is shown with two swelling elements 14axially spaced along the length of the tubular component 12, where theswelling elements 14 are separated by a spacer element 22 placed axiallyadjacent to each side of swelling material 16 of swelling element 14, asshown in FIG. 4. Spacer elements 22 restrict expansion of the swellingmaterial to a radial direction, causing the outer ring 18 to expandoutwards against the inner surface of the outer tubular element, such asa production or injection casing string or liner 23 as shown in FIGS. 7and 8, as the case may be. Spacer elements 22 also act as a seal at theedge of swelling elements 14.

Referring to FIG. 4, the assembly of one embodiment of choke 10 will bedescribed. First spacer element 24 has a threaded connection and isthreaded onto tubular component 12. First swelling element 26 is nextslid onto tubular component 12, followed by second spacer element 28 andsecond swelling element 30. Finally, third spacer element 32 is slidonto tubular component 12. Third spacer element 32 has openings 34 asshown in FIG. 3. Lock wire 36 is fed through openings 34 to allow thirdspacer element 32 to be locked into place as shown in FIG. 4.

Referring to FIG. 5 and FIG. 6, one possible arrangement in which choke10 may be used is shown. FIG. 5 shows SAGD injector 38. Injector 38 hasfive chokes 10, although it will be understood by those skilled in theart that any number of chokes 10 may be used, subject to therequirements of the tasks they are used for. Referring to FIG. 7, choke10 is placed within the SAGD injector 38. Referring to FIG. 8, injector38 has flow control devices 40 to control the flow of steam into thewellbore through slots 33 in casing string 23. Slots 23, which may alsobe openings of other shapes, such as circular holes or a screen also actas a screen for sand control and allow the passage of water andhydrocarbons. During use of the depicted example, steam is passedthrough the interior of injector 38 into the well via flow controldevices 40 and slotted liner 23. The metal of tubular component 12conducts heat to swellable material 16, which may further cause swellingmaterial 16 to expand. Spacer elements 22 limit the expansion ofswelling material 16 in the radial direction, causing it to expandradially and moving outer ring 18 outward to engage the inner surface ofcasing string 23. The seal may not be air-tight, and may be a leaky sealas required and is used to prevent or reduce the amount of injectedsteam or other fluids, such as hydrocarbons, that travels along theannular space inside of casing string 23. Outer ring 18 is preferably ametal, split ring with overlapping ends as shown, which allows it toexpand radially and still sufficiently engage the inner surface ofcasing string 23. Ideally, swelling material 16 is selected such thatthe outward pressure is sufficient to press outer ring 18 outward, butnot sufficient to create a binding or high friction engagement betweenouter ring 18 and the inner surface of casing string 23. This engagementpermits choke 10 to slide axially and shield swellable material 16 inthe case of changing temperatures of the well causing expansion andcontraction of the work string. Outer ring 18, after swelling ofswelling material 16 also serves to centralize tubular component 12. Theuse of chokes 10 remove the need for expansion joints and potentialleaks resulting from such joints and provide access to tools down hole.

As will be understood, the design and use of choke 10 will depend on therequirements of the reservoir, the configuration of the injectionnozzles or ports and their placement, etc. Furthermore, the use of choke10 can provide zonal isolation without the use of expansion joints. Inan alternative embodiment of the invention choke 10 may have acentralizer (not shown) to prevent outer ring 18 from being crushed.

One example of choke 10 will now be described. Choke 10 may be used as aSAGD or cyclic flow choke device. There are several applications for thechoke 10 for flow restriction. It may be placed for multi stage zonalrestriction as shown in FIGS. 5 and 6, or as an above the liner packeras a positive pressure choke for back side inert gas injection (notshown). Choke 10 may use high temperature swellable rubber to engage theouter ring or rings 18. This allows outer rings 18 not to be fullyengaged downhole, but to drift until it is necessary to expand to engagethe outer casing string 23. Presently, existing products require thehole to be cleaned and clear of debris so it won't get stuck or act likea scraper. When the wells are shallow and deviated, it is a challengepushing all the tools downhole in a multi zone completion. Choke 10 willstill require some hole cleaning but drag will be less of an issue withthe presently described choke 10. Each outer ring 18 may act as a chokeoff point without providing a positive pressure seal. As such, choke 10only provides a flow reduction at the metal to metal contact which wouldallow the choke 10 to slide up or down hole due to the expansion of theliner and injection string during temperature change, which couldotherwise lead to buckling on the casing string 23. The choke 10 canstill act as a flow diverting and pressure choke tool. Without buckling,it then extents the life of the well service life and reduces the amountof tools in the hole that may cause a leak problem. The swellable rubbermaterial can be configured to expand at various rates to control theenergy on the expansion ring or rings engagement load. Reducing the loadreduces drag but also reduces the choke flow. An optimized balance ofacceptable drag, zonal pressure, choke control and buckling may bedetermined before installation. The packer can be custom designed withvarious options of metal rings and swellable outer rings. The metalrings can sandwich between swellable rings to increase the pressure holdwhile still maintaining movement.

Further, in the methods taught herein, the various acts may be performedin a different order than that illustrated and described. Additionally,the methods can omit some acts, and/or employ additional acts.

These and other changes can be made to the present systems, methods andarticles in light of the above description. In general, in the followingclaims, the terms used should not be construed to limit the invention tothe specific embodiments disclosed in the specification and the claims,but should be construed to include all possible embodiments along withthe full scope of equivalents to which such claims are entitled.Accordingly, the invention is not limited by the disclosure, but insteadits scope is to be determined entirely by the following claims.

1. A swellable choke comprising: a tubular component; at least oneswelling element, each swelling element comprising: a swelling materialcarried by the tubular component, the swelling material increasing insize as the tubular component encounters a triggering substance; and aring carried by the tubular component, the outer ring having an outersurface that moves from a first diameter to an expanded diameter as theswelling material swells.
 2. The swellable choke of claim 1 wherein thetriggering substance comprises water.
 3. The swellable choke of claim 1wherein the triggering substance comprises a hydrocarbon.
 4. Theswellable choke of claim 1, wherein the ring is a split ring.
 5. Theswellable choke of claim 4, wherein the ring is made from spring steelor a composite, resilient material.
 6. The swellable choke of claim 1wherein the ring is configured to protect the swelling element fromwear.
 7. The swellable choke of claim 1 wherein the swelling material isin thermal contact with the tubular component.
 8. The swellable choke ofclaim 7, wherein the swelling material further swells as a result of achange in temperature.
 9. The swellable choke of claim 1, furthercomprising two or more swelling elements axially spaced along thetubular component.
 10. The swellable choke of claim 1, furthercomprising a spacer element positioned axially adjacent to each side ofthe swelling material.
 11. The swellable choke of claim 1, wherein thespacer elements restricts expansion of the swelling material to a radialdirection.
 12. The swellable choke of claim 1, wherein the tubularcomponent is a mandrel.
 13. A method of treating a hydrocarbon-producingwell, the method comprising the steps of: providing a swellable choke asclaimed in claim 1; attaching the swellable choke in line with a tubingstring; inserting the tubing string into the hydrocarbon-producing well;changing at least one downhole condition to cause the swellable choke toswell and engage an inner surface of the hydrocarbon-producing well. 14.The method of claim 13, wherein the downhole condition is changed bycausing at least one of water and hydrocarbons to come into contact withthe swellable choke.
 15. The method of claim 13, wherein the downholecondition is changed by changing the temperature to which the swellablechoke is exposed.
 16. The method of claim 13, further comprising thestep of allowing the ring to slide along an inner surface of thehydrocarbon-producing well as the swellable choke moves along thehydrocarbon-producing well.
 17. The method of claim 14, wherein thedownhole condition is changed by changing the temperature to which theswellable choke is exposed.